Delta-plain Sandstone Research Articles

Sedimentology and reservoir characteristics of delta plain reservoirs: An example from Messinian Abu Madi Formation, Nile Delta

Delta plain sandstones represent one of the major deltaic hydrocarbon reservoir compartments. The present research provides integrated sedimentological, petrophysical, and petrographical analyses of delta plain reservoirs using an example from the gas-bearing Messinian Abu Madi in the central part of the Nile Delta. The Abu Madi reservoir is interpreted as a tidally-influenced, fluvial-dominated delta plain, and it is subdivided into four sedimentological architectural elements: distributary channel, crevasse channel (straight and meandering), crevasse splays, and interdistributary bay fill. Although the distributary channel has the best reservoir quality (HFU 4 and HFU 5), it is characterized by a high degree of heterogeneity due to the complex interaction between fluvial discharge and tidal currents; straight crevasse channels (HFU 3 and HFU 4) are similar to the distributary channel but have relatively fine grain size and small sand body volume. The meandering crevasse channels are of low reservoir quality (HFUs 1 and 2) due to the formation of point bar muddy inclined heterolithics. According to the results, the delta plain reservoirs are microscopically dominated by quartzose, and litho- and feldspathic quartzose microfacies. The common mud-matrix and poorly sorted fabric due to rapid deposition as well as reworking by tidal/wave currents, that represent the main depositional controls on reservoir quality. Meanwhile, dissolution, anhydrite, quartz, and calcite as well as authigenic kaolinite and chlorite clays are the main diagenetic control factors on reservoir quality.

Sedimentological and diagenetic controls on the reservoir quality of marginal marine sandstones buried to moderate depths and temperatures: Brent Province, UK North Sea

A study of the Brent Group sandstones, in well 211/13-A33 in the Thistle Field, northern North Sea, UK, from a sequence of shoreface, foreshore, delta plain and finally barrier shoreline depositional environments, was undertaken with the aim of contrasting the roles of depositional and diagenetic processes on reservoir quality. These subarkosic and sublitharenite sandstones were buried to ~9000 ft TVDSS and have experienced a maximum burial temperature of about 95 °C. This study utilised wireline and core analysis data, with core samples studied using petrography, XRD, SEM-CL, and SEM-EDS. The dominant diagenetic cements are kaolinite and siderite, with minor quantities of pyrite, chlorite, illite, K-feldspar, calcite and quartz cement. A common sequence of diagenetic events occurred in sandstones from all four depositional environments. The dominant reservoir quality controlling factors are depth-controlled mechanical compaction and variable kaolinite growth, with grain size being an important secondary control. The shoreface sandstones have the highest degree of compactional porosity-loss because they have the greatest quantity of detrital ductile grains. Quartz cement is a minor phase in all formations because these sandstones have only just exceeded the temperature threshold for quartz cement growth. Siderite is found in all formations but with the greatest quantity found in the shoreface and delta plain sandstones, since these environments were most enriched in detrital iron minerals such as biotite and chlorite. The shoreface sandstones host stratigraphically-localised, pore-occluding calcite cement that has compartmentalised the reservoir. Overall, the foreshore and delta plain sandstones have the best reservoir quality because they have (i) few ductile grains resulting in low degrees of compaction, (ii) low quantities of pore-filling cement and (iii) they tend to be medium-grained. In contrast, the shoreface sandstones and barrier shoreline sandstones have poorer reservoir quality as they have (i) moderate to large quantities of ductile grains, (ii) moderate quantities of pore-filling cement and (iii) they tend to be fine- or very fine-grained. Detrital sand mineralogy and grain size vary as a function of depositional environment and these have subsequently played a major role in linking diagenesis and reservoir quality to depositional environment.

Sequence stratigraphy, paleogeography, and coal accumulation in a lowland alluvial plain, coastal plain, and shallow-marine setting: Upper Carboniferous–Permian of the Anyang–Hebi coalfield, Henan Province, North China

To study the stratal stacking patterns and controls on coal accumulation in a lowland alluvial plain, coastal plain, and shallow-marine setting, the depositional facies, sequence stratigraphy, and paleogeography of the Carboniferous–Permian strata in the Anyang-Hebi (Anhe) coalfield, Henan Province, northern China were analyzed based on borehole cores. Ten facies were grouped into four facies associations, which represent alluvial plain, delta plain, delta front and prodelta, and offshore marine depositional environments. Ten sequences (S1 to S10, in ascending order) were defined on the basis of vertical facies stacking patterns. Sequences S1–S3, of Moscovian to early Asselian age, are composed mainly of offshore marine carbonate and mudstone, prodelta and delta front mudstone and sandstone, and delta plain sandstone, mudstone and coal. Sequences S4–S9, late Asselian to Wuchiapingian in age, consist of delta plain sandstone, mudstone and coal. Sequence S10, corresponding to the Changhsingian stage, is composed mainly of alluvial plain sandstone and mudstone. From S1 to S10, the Anhe coalfield experienced an environmental evolution from offshore marine, prodelta and delta front through delta plain to alluvial plain environments, an evolution from a low-accommodation to a high-accommodation setting, and a paleoclimatic change from humid to semi-arid conditions. Coal accumulation was controlled by a combination of relative sea-level fluctuation, paleoclimate and paleogeography. The cyclothemic nature of S2, including presence of parasequences, and the significant sea-level fall interpreted at the base of S4 may be related to Gondwanan ice dynamics in the late Carboniferous–early Permian. The thick coals are concentrated in the transgressive systems tracts of S2 and S4. The results of this study provide new insights into the environmental evolution of Carboniferous–Permian lowland alluvial plain, coastal plain and shallow-marine successions of the northern subtropical paleolatitudes and the controls on coal deposits in North China.

Optimum Development in Mature Fields: Sanga-Sanga Assets, Indonesia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 158716, ’Renewal Plan: Efficient Strategy for Optimum Development in Mature Fields - A Success Story From Sanga-Sanga Assets, Indonesia,’ Andre Wijanarko, Bambang Ismanto, and Robhy Permana, VICO Indonesia, and Italo Pizzolante, Eni, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22-24 October. The paper has not been peer reviewed. VICO Indonesia is the operator of the Sanga-Sanga production-sharing contract (PSC) in Indonesia. Against a backdrop of 46% annual base decline, VICO generated and implemented an integrated and aggressive work program called the Renewal Plan. This is an integrated approach between reservoir management and technology application. This plan proved to be an efficient example of better reservoir management for optimum development of mature assets. Introduction The Sanga-Sanga acreage is located onshore in the Mahakam delta, East Kalimantan, Indonesia. The acreage is located within the Kutai basin, which is characterized by the Samarinda anticlinorium, with a series of highly prolific anticlines. Hydrocarbon accumulations are most often located within a series of mid-Miocene upper-delta and delta-plain sandstone reservoirs, and are principally characterized by fourway dip closure or two-way structural/ stratigraphic traps. VICO Indonesia has been exploring and developing this PSC acreage actively since 1968. There are seven producing fields (Fig. 1): Badak, Nilam, Semberah, Mutiara, Beras, Pamaguan, and Lampake. These together produce 385 MMscf/D of gas and 14,500 B/D of liquids from 420 active wells, which have mixed wellbore completions (single, dual-selective, monobore, dual-monobore, and horizontal). The surface facilities supporting the production include four main production centers, 12 gathering stations, and more than 90 compressors. After 40 years of production, these fields have now reached a fairly mature stage; most of the penetrated reservoirs/ tanks have been depleted from original pressures. Coupled with the annual production decline, this condition has resulted in significant challenges to delivering a continuous economic and efficient field-development strategy while maximizing field production. Renewal Plan VICO carried out a reserves-reassessment study—an integrated approach involving reservoir management and technology applications conducted by a multidisciplinary team. The seven components of the Renewal Plan are described in the following subsections. Securing Base Production. Securing base production is one of the keys to achieving a production target. Well monitoring and surveillance are the primary methods by which base production is secured. Previously, VICO wells were monitored by frequent production tests, mostly depending on human surveillance. In the Renewal Plan, automated real- time monitoring well surveillance of wellhead-pressure and flow-rate data on each well was implemented. This real- time wellhead surveillance (RTWHS) transmits the data from the wellsite to the VICO server; then, it is stored in a database. Operators and production engineers could monitor the behavior of the well in real time. This system has proved to minimize well downtime, leading to aggressive well reactivation. This installation has also become standard for new wells. Currently, 90% of VICO’s active wells are equipped with RTWHS.

Upper cretaceous to paleocene depositional sequences and sandstone petrography of southwestern Patagonia (Argentina and Chile)

Upper Cretaceous to Paleocene strata exposed along the Andean margin of Patagonia south of 50°S were deposited in a foreland basin and comprise a complex transition from continental to marine facies. Three unconformity-bounded sequences are observed within the sedimentary succession studied. Sequence 1 (upper Campanian) displays a rapid north-to-south transition from upper delta plain mudstones (Cerro Fortaleza Formation) through lower delta plain and subaqueous delta plain sandstones (La Anita Formation) to delta-slope and basinal turbidites (Alta Vista and Tres Pasos Formations). Sequence 2 (Maastrichtian-Paleocene) was initiated with braided river sediments (La Irene Formation), deposited over a Type II unconformity ( sensu Vail et al., 1984). These rocks are overlain by meandering fluvial sandstones and mudstones (Chorrillo Formation) that interfinger to the south with fossiliferous shallow marine sandstones (upper Cerro Cazador Formation). Sequence 3 (Paleocene) is composed of shallow marine conglomerates and crossbedded sandstones (Calafate and Cerro Dorotea Formations). These rocks are separated by an angular unconformity from subjacent units. Sandstone petrographic analysis indicates the presence of two main petrofacies within the rocks studied. A quartz-rich petrofacies, present to the north of the basin during late Campanian to early Maastrichtian time, was derived from continental crustal block and recycled orogen sources that were possibly exposed to the northwest of the basin. The second petrofacies (volcanic-rich petrofacies) was restricted to the south of the basin during the late Campanian to early Maastrichtian, but covered the entire area during the late Maastrichtian and Paleocene. These sediments were derived from a dissected magmatic arc located to the west of the study area. The presence of abundant tuffaceous intercalations, as well as fresh andesitic fragments, indicates contemporaneous volcanism near the Cretaceous/Tertiary boundary. The marked contrast in observed petrofacies may be a reflection of the major Andean segmentation at 49°S, at the present intersection of the Chile Rise with the South American coast.

Sandstone Diagenesis and its Variation with Deltaic Depositional Environments, Upper Cretaceous, Southern Rio Escondido Basin, Coahuila, Mexico: ABSTRACT

Prodelta, delta-front, and delta-plain sandstones and shales were deposited in a wave-dominated lobate delta in the Rio Escondido basin during Campanian and Maestrichtian time. The End_Page 529------------------------------ composite diagenetic sequence based on petrographic analyses of over 300 thin sections from sandstone samples from these environments consists of: (1) bioturbation of sediment and compaction of ductile grains before cementation; (2) infiltration of minor amounts of pedogenic illite and precipitation of chlorite and minor amounts of smectite; (3) cementation by euhedral, syntaxial quartz overgrowths; (4) extensive poikilotopic calcite cementation; (5) widespread dissolution of calcite; (6) precipitation of kaolinite as patches in some of the dissolution pores; (7) replacement of calcite and framework grains by iron-rich carbonates (ankerite-ferroan dolomite, ferroan calcite, siderite). The relative intensities of these diagenetic events, and thus porosity and permeability, are controll d by and vary with the environment of deposition of the sandstones. The two main factors controlling the differences in diagenetic features within the environments are (1) original composition of the sands, and (2) geometry of the sandstone bodies. Prodelta siltstone and very fine-grained sandstone, deposited as thin frontal-splays, are enclosed in thicker sequences of marine shale. These rocks (dominantly feldspathic litharenite and lithic arkose) typically have the lowest porosity (x = 4%) and permeability. (x = 1 md) of the three environments. Primary porosity was destroyed early by extensive bioturbation and by widespread calcite cementation (x = 23%). The thicker, impermeable shale above and below the thin, lenticular sandstone bodies served as barriers to subsequent fluid migration, thus inhibiting any creation of secondary porosity by dissolution and any later diagenetic changes. Channel-mouth-bar and sheet-sand deposits of the delta-front facies are generally more quartz-rich and thus, due to a greater stability of the quartz grains, underwent the least amount of compaction. Consequently, calcite cementation was widespread; later dissolution of calcite produced secondary porosity up to 28% and permeability up to 557 md. These fine to medium-grained sandstones (dominantly feldspathic litharenite, lithic arkose, and subarkose) have the highest porosity (x = 18%) and permeability (x = 81 md) of rocks from the three facies. Delta-plain fine to medium-grained sandstone has intermediate porosity (x = 8%), but low permeability (x = 1 md). These sandstones (primarily feldspathic litharenite) have the highest concentration of sedimentary and volcanic rock fragments, which were squashed during compaction and altered during burial. Thus, only a relatively small amount of pore space remained for calcite cementation. Kaolinite cement filled in most of the secondary porosity created by dissolution of early formed calcite. End_of_Article - Last_Page 530------------

Depositional Environments and Reservoir Morphologies of Channel Sandstones: ABSTRACT

Channel sandstones are deposited in fluvial channels, fluvial-dominated deltas, submarine channels, and channel-dominated submarine fans on shelves and slopes of many basins. Excellent models of these channel-sandstone depositional environments and reservoirs are in Upper Pennsylvanian and Lower Permian sediments of the eastern shelves and slopes of the west Texas Permian basin. In dip-trending paleodrainage systems on superimposed alluvial plains, sandstone reservoirs are in single and multiple strike-oriented point bars in meander belts, and longitudinal and transverse bars in braided belts. By differential compaction these sandstone belts may produce oil where they drape over buried paleotopographic features such as reefs, structures, and sandstone bodies. Conversely, eservoirs may be found in these buried features by recognizing diversions in the trend of overlying sandstone belts. Oil and gas in sediments adjacent to channels may be trapped by nonpermeable channel-fill barriers. Seismic cross sections of meander belts can clearly show convex-downward bases. Stratigraphic traps are in thin distributary-channel and delta-plain sandstone facies of shelf-elongate deltas on shelves. Shelf-margin lobate deltas have reservoirs in thick distributary-channel, delta-plain, and delta-front sandstone deposits. Packages of fine-grained, lenticular turbidites can be correlated in submarine channels and fans. Stratigraphic cross sections reveal levees that trap oil in turbidites. Many slope-sandstone facies have been stratigraphically miscorrelated by hundreds of feet with lower sandstone formations. Regional and local models of shelf and slope channel-sandstone systems and reservoirs and the subsurface methods that reveal them should aid research, production, and exploration geologists. This paper is an attempt to bridge the gap between research and applied geology by describing how the depositional environments of channel sandstones are recognized in the subsurface and how oil and gas are trapped in these sandstones. End_of_Article - Last_Page 2465------------

Energy Resources of Water-Bearing Geopressured Reservoirs: ABSTRACT

Estimates for the total gas resource in place in geopressured Tertiary sandstone reservoirs along the Gulf Coast range from 3,000 to 100,000 Tcf (85 to 2,832 trillion cu m). This wide range in estimates was the incentive for initiating an extensive research effort in Texas and Louisiana to obtain more reliable data on geologic, engineering, environmental, legal, and social aspects of developing the geopressured resource. These studies include investigation of the available heat and hydraulic energy present in these aquifers in addition to the methane. All resource calculations are based on interpretations of total sandstone thickness, lateral extent of reservoirs as defined by depositional and structural boundaries, porosity and permeability, reservoir drive, salinity, te perature, pressure, and methane solubility. Diverse estimates arise from inadequate knowledge concerning these critical parameters. To obtain answers to the many questions, an extensive research program has been established at The University of Texas at Austin by the Bureau of Economic Geology and the Center for Energy Studies. The bureau has been conducting broad regional geologic studies (for resource assessment and geothermal fairway delineation) End_Page 1276------------------------------ and detailed, site-specific studies (to identify potential test-well sites). The Tertiary strata of the Texas Gulf Coast comprise a number of terrigenous depositional wedges which dip and thicken into the gulf basin. Some of the wedges, Wilcox, Vicksburg, and Frio, thicken abruptly in a downdip direction as a result of contemporaneous movement along growth faults which developed near the ancient shorelines. Thick sections of sand and mud accumulated on the down side of these growth faults; expulsion of water from these downfaulted sediments was impeded by the faults and, with increased burial and overburden, high fluid pressures characteristic of this geopressured zone developed. The lack of water circulation in these geopressured reservoirs resulted in the increase in the temperature gradient from approximately 1°F/100 ft (1.9°C/100 m) in the hydros atic zone to 2°F/100 ft (3.7°C/100 m) in the geopressured zone. The regional studies, followed by detailed local investigations, were pursued to delineate prospective areas for production of geopressured energy. A prospective area must meet the following minimum requirements: (1) reservoir volume of 3 cu mi (12.5 cu km), (2) minimum permeability of 20 md, and (3) fluid temperatures of 300°F (149°C). Several geothermal fairways were identified in the Frio Formation and Wilcox Group as a result of these studies. Only the Brazoria fairway, however, meets all of the specifications for a geothermal prospect in the Frio. The DeWitt fairway best meets the requirements in the Wilcox. In the Brazoria fairway, located in Brazoria and Galveston Counties, Texas, several hundred feet of deltaic sandstones have fluid temperatures greater than 300°F (149°C). Permeabilities within these reservoirs are greater than 20 md; this high permeability is related to secondary leached porosity, which developed in the moderate to deep subsurface. The geothermal test well (Department of Energy and General Crude Oil 2 Pleasant Bayou) is located within the Austin Bayou prospect, Brazoria fairway. The reservoir consists of 250 to 300 ft (75 to 90 m) of sandstone with core permeabilities between 40 and 60 md and fluid temperatures from 300 to 350°F (149 to 177°C). The sandstone-shale section within the Austin Bayou area is represented by seven progradational sequences Each sequence is characterized by low-porosity prodelta and distal delta-front shale and sandstone at the base grading to porous distributary-mouth bar and delta-plain sandstone and shale at the top. The older and deeper depositional sequences represent only the distal part of the lobate delta, and the later events represent the entire deltaic complex. The 2 Pleasant Bayou well has been completed to total depth of 16,500 ft (5,029 m) and testing will begin during the last half of 1979. A proposed well in the DeWitt fairway, DeWitt County, Texas, will test the deep sandstone reservoirs in the lower part of the Wilcox Group. More than 300 ft (90 m) of deltaic sandstone is present within a fault block 3 mi (5 km) wide and 15 mi (24 km) long. The Pleasant Bayou geopressured geothermal test well is expected to provide the first reliable data concerning many aspects of producing energy from the water in the geopressured zone. However, this single well will not answer all of the questions nor prove or disprove the feasibility; several additional wells are planned for both Texas and Louisiana. End_of_Article - Last_Page 1277------------

Potential for Production of Geopressured Geothermal Energy, Texas Gulf Coast: ABSTRACT

Tertiary strata of the Texas Gulf Coast include several terrigenous depositional wedges, some of which thicken abruptly at their downdip ends as a result of contemporaneous movement of growth faults and underlying salt. The Frio Formation is one of these wedges. Broad regional studies, followed by detailed local investigations, were pursued in order to delineate prospective areas for production of geopressured geothermal energy. A prospective area must meet the following minimum requirements: reservoir volume of 3 cu mi (12.5 cu km), minimum permeability of 20 md, and fluid temperatures of 300°F (149°C). Several geothermal fairways were identified as a result of the Frio study. Only the Brazoria fairway, however, meets all of the specifications for a geothermal prospect. In the Brazoria fairway, located in Brazoria and Galveston Counties, Texas, several hundred feet of deltaic sandstones have fluid temperatures greater than 300°F (149°C). Permeabilities within these reservoirs are greater than 20 md; this high permeability is related to secondary leached porosity, which developed in the moderate to deep subsurface. The geothermal-test-well site is located within the Austin Bayou prospect, Brazoria fairway. The reservoir will consist of 250 to 300 ft (75 to 90 m) of sandstone with core permeabilities between 40 and 60 md and fluid temperatures from 300 to 350°F (149 to 177°C). The sandstone-shale section within the Austin Bayou area is represented by seven progradational depositional sequences. Each sequence is composed of a gradational vertical succession characterized by low-porosity prodelta and distal delta-front shale and sandstone at the base grading to porous distributary-mouth-bar and delta-plain sandstone and shale at the top. The older depositional sequences represent the distal half of a lobate delta, and the later events represent the entire deltaic complex. More than 10 billion bbl of water are in place in these sandstone reservoirs of the Austin Bayou prospect; there should be approximately 400 Bcf of methane in solution in this water. Only 10% of the water and methane (1 billion bbl of water and 40 Bcf of methane) will be produced without reinjection of the waste water into the producing formation. Reservoir-simulation studies indicate that more than 50% of the methane can be produced with reinjection. End_of_Article - Last_Page 417------------

Pennsylvanian Fan-Delta Sandstones, Palo Duro Basin, Texas: ABSTRACT

Pennsylvanian sedimentation in the Palo Duro basin was strongly influenced by tectonic events. Highlands surrounding the basin were uplifted early in the Pennsylvanian Period and were major sources of clastic sediment. Arkosic sandstones (granite wash) contain abundant feldspar and granite rock fragments derived from exposed Precambrian basement rocks. Granite wash deposits are thickest in the northeastern and northwestern parts of the basin, and lobes of sandstone extend to the southern basin margin. Individual beds, which are 10 to 40 ft (3 to 15 m) thick and are laterally discontinuous, cannot be correlated more than a few tens of miles. Granite wash deposits vary from medium sandstone to conglomerate, and upward-fining sequences are common. These sandstones contain scours and large-scale trough or foreset cross-beds. Limestone commonly is interbedded with granite wash sandstone and shale. Thick wedges of Pennsylvanian granite wash adjacent to mountain fronts are characteristic fan-delta deposits. Coarse clastic material was carried off the uplifts to adjacent fans by high-gradient braided streams. Near the source areas, sediments are entirely terrigenous clastics, which were probably deposited in subaerial delta-plain environments. Coal and thin limestone beds are interbedded with delta-plain sandstones. Carbonates become more abundant downdip where they were deposited periodically in subaqueous, distal-fan delta environments. Periodic movement along faults may have been responsible for the initiation of major clastic cycles. End_of_Article - Last_Page 2116------------

Testing Geopressured Geothermal Resource, Frio Formation, Texas Gulf Coast: ABSTRACT

Drilling of the first well designed to test geopressured geothermal resource for a sustained period of time was initiated in July 1978. Regional and site-specific geologic and engineering studies supportive of this site were conducted by the University of Texas Bureau of Economic Geology and Department of Petroleum Engineering/Center for Energy Studies with funds from the U.S. Department of Energy. The area sought during these studies needed reservoir volume of 3 cu mi (12.5 cu km), minimum permeability of 20 md, and fluid temperatures of 300°F (149°C). The Brazoria fairway, Brazoria and Galveston Counties, Texas, best met these specifications and the Austin Bayou Geothermal Prospect was developed in this fairway. Funds for drilling the Nos. 1 and 2 Pleasant Bay u geothermal test wells in the Austin Bayou Prospect were provided by DOE; the operator of the wells is General Crude Oil Co. The geopressured sandstone reservoirs are in the lower part of the Frio Formation between the depths of 14,000 and 17,000 ft (4,200 and 5,100 m). The sandstone units are at the top of at least seven progradational deltaic cycles; cumulative thickness of all permeable sandstone units is 250 to 300 ft (75 to 90 m). Each deltaic cycle is composed of a gradational vertical succession characterized by low-permeability prodelta and distal delta-front sandstone and shale at the base grading to permeable distributary-mouth-bar and delta-plain sandstone and shale at the top. Fluid will be produced from the 2 Pleasant Bayou well, stripped of methane and heat, then injected into Miocene sandstones at 6,000 to 7,000 ft (1,800 to 2,100 m) depth in the nearby 1 Pleasant Bayou disposal well. The produced water is expected to have salinities ranging from 50,000 to 80,000 ppm, temperature from 300 to 350°F (149 to 177°C), pressure from 10,000 to 15,000 psi (68,950 to 103,425 kPa) and 40 cu ft (1.2 cu m) of methane per barrel. The 2-year test period will evaluate the feasibility of long-term production of large quantities of water (ultimately 40,000 bbl/day) from geopressured reservoirs. End_of_Article - Last_Page 1595------------

Estimating Water Depths from Analysis of Barrier Island and Deltaic Sedimentary Sequences

A model is proposed for estimating water depths from thicknesses of pro-grading coarsening-upward barrier island and deltaic sequences. The prograding barrier sequence consists of a basal lower shoreface mudstone overlain by middle shoreface interbedded mudstone and sandstone, capped by a sandstone complex of beach-upper shoreface and coastal dune. Sea level coincides with the base of accretionary cross-stratified foreshore beach sandstone. Sediment thickness from this sea-level datum to the base of the lower shoreface mudstone is the same as water depth into which the barriers prograded. The prograding deltaic sequence consists of a basal pro-delta claystone overlain by delta-front interbedded sandstone and mudstone, capped by delta-plain sandstones and other facies in which sea level can be recognized. Sediment thickness from the sea-level datum to the base of the pro-delta claystones is the same as the water depth into which the deltas prograded. Constraints on the model are compaction, subsidence, and transgressions, but these are not a difficulty, provided the method is applied with care. Preliminary data indicates approximate water depths of 2.5 to 12.1 m for Pennsylvanian and Cretaceous barriers, 10 to 24 m for Pennsylvanian and Cretaceous cratonic deltas, and 31 to 89 m for Carboniferous basinal deltas.

Fluvial, Deltaic, and Slope Reservoir Sandstone in West-Central Texas: ABSTRACT

More than 300 Lower Permian sandstone oil and gas fields are present in an area of about 7,000 sq mi on the Eastern shelf and slope of the Midland basin. All these fields appear to be in stratigraphic traps in fluvial, deltaic, and slope depositional environments. Two Lower Permian Cook fluvial sandstone systems extend in a downdip direction across the Eastern shelf to the shelf edge, where progradational Cook sandstone facies form two high-constructive deltas. These are the proximal parts of a thick terrigenous clastic wedge of sediments covering the eastern slope. Outcrops of Cook channel-fill deposits grade upward from conglomerate and quartz sandstone, to gray shale. Downdip from outcrop to the shelf edge, Cook sandstone is present in one meander belt system 82 mi long. The upper 30 mi is about five mi wide and bounded by shale and two thin lenticular limestone beds. The belt narrows to about one mi where adjacent limestone beds are thicker and were more resistant to lateral channel erosion. About 58 mi downdip from outcrop, the meander belt divides into two belts. Each belt is about one mi wide and bounded by shale and thick limestone beds to the shelf edge. Point bars (with characteristic electric-log SP curves), crevasse splays, and/or natural levees are discernible in the meander belts. Many stratigraphic traps are present in point bars, in sandstone belts perpendicular to regional dip, and in belts of sandstone that overlie buried reefs, hills, structures, and other channel sandstones. Paleocreekology is applicable in locating topographic features on the paleoshelf. Both Cook sandstone deltas, nearly joining, are in an area of 295 sq mi. Delta-plain facies consist of interbedded dark gray shale, fine-grained, lenticular sandstones, and thin coal lenses underlain by thick, medium-grained sandstone facies in distributary channels. Electric-log SP curves of the channel sandstones are characteristic. Delta front distributary mouth bar and sheet-sandstone facies overlie thick prodelta shale and thin, lenticular sandstone. The Group 4000 Cisco sandstone field is the only oil field of any significance in the two deltas. It produces from delta-plain sandstone facies. West of the shelf edge, the Cook wedge of shale and sandstone lenses reaches a maximum thickness of about 1,300 ft at midslope and thins basinward. The base is a maximum gradient of about 3° at midslope. The Northeast Bloodworth Canyon sandstone field produces from Cook sandstone, probably a turbidite and slump deposit, evidently deposited in a submarine channel. The Jameson Strawn sandstone field, about 35 sq mi in area, produced from Cook lower slope sandstone lenses, probably part of a submarine fan. End_of_Article - Last_Page 420------------

Deltaic Sedimentation and Growth Faulting, Upper Cretaceous, Colorado: ABSTRACT

The upper Pierre, Fox Hills, Laramie, and Arapahoe Formations in the western Denver basin record deltaic sedimentation during the final regression of the Cretaceous sea from eastern Colorado. Prodelta shales and siltstones (Pierre Formation) are overlain by delta-front sandstones (Fox Hills), and delta-plain sandstones, claystones and coals (Laramie Formation). The younger conglomerates of the Arapahoe Formation are braided channel deposits of the fluvial system. Two types of penecontemporaneous (growth) faulting are recognized in 5 mi of outcrop from Golden south to Interstate 70. One type of faulting cuts delta-plain sediments, resulting in a thickness increase of the Laramie Formation from 330 to 530 ft in a horizontal distance of 800 ft. By normal fault movement at the time of sedimentation, an extra 200 ft of lower Laramie sandstone, with minor claystone and thin coal, was deposited on the downthrown side of the fault. The northwest-trending fault plane curved downward toward the south from a dip of about 60° to a low-angle bedding plane fault. A second type of faulting records slumpage on oversteepened prodelta slopes created by seaward progradation of the shoreline. One slide block of shallow-water distributary-mouth sandstone (Fox Hills) about 100 ft thick moved southward down the prodelta slope into water depths estimated to be from 100 to 175 ft and was subsequently buried by prodelta clays (Pierre). The geographic position of these growth faults in the delta sequence appears to have been controlled by recurrent movement of deep-seated faults in the Precambrian basement which at the time of Laramie deposition was at depths in excess of 10,000 ft. Growth faulting heretofore unrecognized in the Cretaceous of the Rocky Mountain area, may be a common occurrence in the areas of deltaic sedimentation. Some abrupt thickness changes may be explained more readily by this process than by the commonly invoked theories of facies change or unconformities. End_of_Article - Last_Page 661------------

Fluvial--Deltaic Facies of the Castlegate Sandstone (Cretaceous), East-Central Utah

ABSTRACT The Castlegate Sandstone is one of several regressive sandstone tongues of the Late Cretaceous Mesaverde Group of east-central Utah. The Castlegate is the rock record of a fluvial-delta complex. The sedimentary facies change seaward (east) from piedmont red-bed conglomerates in central Utah to fluvial sandstones, then delta-plain sandstones, mudstones, and coals, and farther east to shoreline sandstones and finally delta-front interbedded sandstones and mudstones. The Castlegate wedges out as a rock unit into mudstones of the Mancos Shale near the Utah-Colorado state line. The depositional facies differ significantly in paleocurrent directions, measured on imbricated pebbles in conglomerates and trough cross-beds in sandstones. Paleocurrent directions in piedmont conglomerates are polymodal but with a dominant eastward directions. The average paleocurrent direction for fluvial sandstones is eastward but there is considerable variation among outcrops. Distributary channel sandstone of the delta-plain facies have polymodal paleocurrent directions due to tidal fluctuations. The shoreline sandstones have bimodal cross-bed directions both landward (west) and seaward. Delta-front bottom currents flowed landward. Grain-size decreases eastward from the piedmont through delta-front facies. Most Castlegate sandstones and siltstones from all facies are texturally similar to Holocene fluvial sands. Sedimentary rocks uplifted in western Utah and eastern Nevada during the Laramide orogeny were the source for Castlegate detritus. The grains consist largely of quartz plus fragments of chert, orthoquartzite sandstone, carbonate rock, and mudstone. Clay minerals are kaolinite, illite, and montmorillonite. The cements are silica, carbonates, and iron-oxides. Feldspars, micas, and metamorphic fragments constitute only a few percent. Non-opaque heavy minerals are 99% zircon, tourmaline, and rutile, largely reworked from older sandstones.

Delta Front-Delta Plain Fades of the Pennsylvanian Haymond Formation, Northeastern Marathon Basin, Texas

The sandstone beds of the middle and upper parts of the Haymond Formation cropping out on the Allison Ranch, Marathon Basin, west Texas, are divisible into several genetic categories based mainly on the external morphology, arrangement and boundary relations with adjoining rocks, nature of bedding, fossil, and quartz content. The two major genetic types are sheet sands of the delta front and multiple braided distributary channel sands of the overlying delta plain facies. That the delta front was subjected to higher physical energy than the delta plain is suggested by the relatively high quartz content which increases in the more seaward facies. The stratigraphic position of these delta front and delta plain sandstones of the middle and upper Haymond overlying the prodelta sediments of the lower Haymond reflects deltaic progradation in the Marathon area during Middle Pennsylvanian time.